This section is intended to introduce the reader to various aspects of art, which may be associated with exemplary embodiments of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with information to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that these statements are to be read in this light, and not necessarily as admissions of prior art.
In the drilling of wells (for example, oil and gas wells) using the rotary drilling method, drilling fluid is circulated through a drill string and drill bit and then back to the surface by way of the wellbore being drilled. The fluid is processed to remove drill solids and to maintain desired properties before is it re-circulated to the well. The drilling fluid may have multiple purposes, including 1) cooling and/or lubricating the drill bit; 2) maintaining hydrostatic pressure on the subterranean formation through which the wellbore is drilled thereby preventing pressurized formation fluid from entering the wellbore; and 3) circulating cuttings out of the wellbore. During drilling operations, some amount of fluid will be lost, which lost amount is often referred to as “lost returns.” Some forms of loss are considered acceptable and are expected. For example, some amount of drilling fluid is lost due to the permeability of the formation. As mud flows into the small openings in the rock, the solids within the fluid will eventually plug the openings and form a filter cake on the wellbore wall. The loss volumes are small and decline with time. Additionally, drilling fluids may be lost upon formation of a fracture in the wellbore wall providing an outlet for the drilling fluids. The solids in the mud are not capable of plugging the open gap and losses can be unexpected, uncontrollable, and/or in unacceptable volumes.
The mechanical properties of the subterranean formations into or through which wellbores are drilled will vary. These properties, and the fluid pressure in the wellbore, determine whether losses will occur, and the nature of the loss. For example, the permeability of the formation will determine how quickly the filter cake forms on the wellbore wall and how much drilling fluid is lost before an effective filter cake is formed. The term “spurt loss” is generally used to refer to the volume of drilling fluid that passes through a filter medium (here, the permeable wellbore wall) prior to the formation of a controlling filter cake. Conventionally, drilling fluids have been designed to minimize the spurt loss through the permeable wellbore wall. The resulting filter cakes form quickly and are generally very thin. Conventional drilling fluids have been optimized in a number of different ways for the formation of filter cake on wellbore walls. However, these attributes are not effective in stopping losses to fracture formation. The problem of lost returns due to fracture formation is treated by the industry in a variety of ways, but solutions are still needed that are more effective and predictable.
Another important property of subterranean formations is the formation integrity, which varies along the length of the wellbore. The formation integrity is often a function of several factors, including the composition of the formation and the depth of the formation. The formation integrity is defined as the wellbore pressure at which a fracture will form in the wellbore wall and fluid will be lost. When the wellbore pressure exceeds the formation integrity the rock is forced open and mud flows into the opening. The pressure required to open the wellbore to create a fracture is largely equal to the stress stored in the surrounding rock that is holding the wellbore closed. This stress comes from the weight of the rock and fluids above the particular depth of interest. This weight is referred to as overburden. Rock properties also play a role because the stress that will be created by a given overburden varies with specific rock properties. For example, a formation buried deeply in the earth may have 10000 psi of overburden, which may create a minimum rock stress of 7000 psi in a given formation. The wellbore pressure required to force the wellbore wall open will typically be only slightly higher than 7000 psi. The shape of the opening will be narrow and tall and is referred to as a fracture. Because the overburden and rock properties will vary from one interval, or region of the formation, to another, the integrity of the formation varies along the length of the wellbore. Drilling may progress well in intervals with higher containment stress, but fractures and corresponding drilling fluid losses may occur as strata or intervals are penetrated where the formation integrity is lower.
Heretofore, the opening of a fracture has been discussed in relation to a formation's integrity. The formation integrity at a particular point in the wellbore may also be referred to as the fracture gradient at that location. The fracture gradient is often expressed as pressure divided by depth and corresponds to the pressure the wellbore wall is able to sustain before a fracture is created. The fracture gradient of a particular interval or region of a wellbore equals the pressure required to initiate fracture growth divided by depth of the location. The fracture gradient of a particular interval may also be expressed in “equivalent mud weight” (EMVV). This is the density that a column of fluid must have to exert a given gradient of pressure, and may be expressed in pounds per gallon (ppg). If a fracture is created and forced open, the two faces of the fracture continue to push back and attempt to close with a force equal to the surrounding rock stress. This force is referred to as Fracture Closure Stress, or “FCS”.
A primary source of the pressure that may induce a fracture opening is the hydrostatic pressure applied on the wellbore wall by the drilling fluid being circulated in the wellbore. One important property of the drilling fluid is the fluid's mud weight or mud density, which is its mass per unit volume. The drilling fluid's mud weight is important as it determines the hydrostatic pressure in the well at any given depth, which prevents inflow into the well and collapse of the wellbore, and which causes fractures when the hydrostatic pressure exceeds the formation integrity or fracture gradient. When a drilling fluid is being circulated, additional pressure is applied against the wellbore wall due to friction-induced pressure drop. Accordingly, drilling operations often consider the equivalent circulating density (ECD) of a drilling fluid, which equals the dynamic pressure drop in the annulus from the point being considered to the surface, plus the static head of the fluid due to it's density. Because the drilling fluid in the wellbore may at different times be circulating in the wellbore or stationary in the wellbore, determining and controlling the hydrostatic pressure applied by the drilling fluids under both conditions is important for maintaining the desired integrity of the wellbore (avoiding fractures from overpressure and collapse from underpressure).
Conventionally, a section of wellbore is drilled to that depth where the ECD creates a wellbore pressure that approaches the fracture gradient of the formation adjacent the wellbore. For example, the wellbore may be drilled into an interval known to have lower integrity (due to rock composition, depletion, or other reasons) and correspondingly lower fracture gradient. At that point, a string of casing is installed in the wellbore to stabilize the formation in the previously drilled interval, such as to prevent collapse of the wellbore and/or to prevent inflow of formation fluids, and then the wellbore pressure is reduced to the level tolerable by the lower integrity formation at greater depths. Similarly, if a newly approached interval requires a higher wellbore pressure than a previous interval can support without creating fractures, a casing may be installed to stabilize and/or isolate the previous interval against the increased wellbore pressure required to continue drilling. In general, each added casing string has a smaller diameter than the previous string and can be very expensive and time-consuming to install. In some instances, deep wellbores become impractical to drill due to the number of casing strings needed to complete the well and the reduction in casing and hole size that occurs with each string installed.
FIG. 1 is a graph of depth in meters versus expected pore pressure (line 2) in a formation strata or a formation stratum to be intersected during drilling of a well, expected fracture gradient (line 3) in the strata, and an ECD (line 4) of the drilling fluid to be used. Safe drilling procedures require the ECD (line 4) to lie between the pore pressure and the fracture gradient (lines 2 and 3). At the right side of the FIG. 1, a casing plan is shown based on these curves. The depth of intermediate six casing strings 5 are planned to prevent lost returns, by isolating the strata having low fracture gradient “behind pipe,” and are shown with the casing shoes for each of the six strings at depths 1a, 1b, 1c, 1d, and 1e. 
In the example of FIG. 1, lost returns to the strata in the regions designated “Zone A,” “Zone B” and “Zone C” would be expected because the pressure applied to circulate the well (ECD) is greater than the formation integrity in these three zones with low fracture gradient. The risk of opening a fracture is greatly exacerbated in intervals of the wellbore that have been partially depleted by production resulting in reduced pore fluid pressures, as illustrated in depleted Zones A, B, and C in FIG. 1. Lower fluid or pore pressure in an interval or stratum decreases the stress holding the borehole closed and the fracture gradient in the stratum.
A high lost returns rate into fractures may also occur when there has been no depletion, particularly in wells that are drilled directionally at high angle. When vertical wells are drilled, the integrity tends to increase with drill depth because integrity is increased by the weight of the formations above a given point. In contrast, the integrity in high angle directional wells does not increase as rapidly because the trajectory is generally sideways and the well is not penetrating deeper into the earth. In the extreme example of a horizontal well, there is no increase in vertical depth at all, and there is no change at all in integrity as drilling progresses. However, the circulating pressure continues to increase due to the increasing length of the borehole. When the directional wellbore reaches a certain length, its circulating pressure may exceed the integrity of the formation and losses will occur. When the circulating pressure in a high-angle directional well exceeds the formation integrity, continued drilling may result in unacceptably high lost returns, even though geologic objectives may not have been met. The economic impact of these types of losses may increase as deep water fields mature and pressures in produced intervals decline. Deep water fields are typically developed in formations with low native integrity and with wellbores drilled to great distances from the central structure with high circulating pressures. There are currently few depleted reservoirs in deep water, because the industry has only recently developed the technology to develop these fields. However, further depletion of fluids from these reservoirs may further reduce the fracture gradient in some zones. The combination of high circulating pressures in the high-angle, extended-reach wells and lower fracture gradients common in deep water may make it uneconomical to develop large deposits unless new drilling technology is available.
Losses may also occur when the fluid density required to prevent the wellbore from collapsing in areas of low strength rock exceeds the integrity. Directional wells are more prone to collapse and thus require higher fluid density to drill successfully. The density required to stabilize the wellbore is referred to as the “stability mud weight”. The combination of the higher fluid density requirement for stability and high circulating pressure due to the wellbore length causes losses to be more likely in high-angle, long-throw wells.
If it is observed that returns are lost to a fracture when drilling into a zone, in addition to installing costly casing, two major response avenues are available: 1) reduce the wellbore pressure, and 2) increase the fracture gradient of the formation to exceed the wellbore pressure. If the borehole pressure is reduced below the FCS, the stress around the wellbore will force the fracture closed and fluid losses will stop. If, for a variety of reasons, the pressure cannot be reduced, the borehole pressure will continue to extend the fracture, and losses continue. Consequently, increasing the fracture closure stress (FCS) is the preferred avenue.
It is known that if a fracture is formed that intersects the wellbore and extends into the rock around the wellbore and that fracture is held open by solid material in the fracture, then the fracture gradient at the wellbore is increased. (F. E. Dupriest, “Fracture Closure Stress (FCS) and Lost Returns Practices,” SPE/IADC 92192, Society of Petroleum Engineers, 2005). The great majority of lost circulation treatments in industry work to enhance the wellbore fracture gradient by forming a fracture that is held or propped open. Widening the fracture causes the rock in the immediate region of the wellbore to be compressed, which causes it to push back with greater stress. Thus, the fracture-opening pressure (integrity) increases. The stress travels around the wellbore wall and increases the opening pressure to some degree in all directions. Fractures can be widened by building pressure in the wellbore or within the fracture itself.
The majority of conventional attempts to increase the fracture closure stress apply a discrete treatment to the wellbore. The conventional discrete treatment consists of stopping drilling and then pumping a limited volume of fluid called a “pill” containing Lost Circulation Material (LCM) down the wellbore in an attempt to stop or slow the loss of drilling fluid. The LCM material is typically larger in size than solids in conventional drilling fluids.
The LCM materials interact with the newly formed fracture to prevent additional fluid loss through that fracture. The LCM widens the fracture resulting in an increased fracture closure stress in the region of the wellbore adjacent to the fracture. If the treatment is not successful, casing must be set across the loss zone, which is expensive and time-consuming. There is also the additional expense of the lost fluid.
The vast majority of historical treatments have been discrete operations conducted either when losses first occur, or after the formation interval is fully exposed and drilling stops. Accordingly, fluid losses occur while the drilling progresses through the interval and costs are incurred while the drilling is stopped for the discrete treatment. The success rate in discrete treatments has improved, but the industry has lacked reliable and practical processes for building stress as drilling progresses without interrupting the drilling process.
There are several reasons why a continuous process is desirable. Discrete processes are often effective, but they are used after the losses have already occurred. The drilling must stop because if fluid cannot be circulated back to the surface, the drill cuttings that are being created cannot be removed from the well. Also, drilling equipment costs continue during the non-productive time required to stop and treat the loss. At current rig rates, this non-productive time may total tens to hundreds of thousands of dollars per day. Other effects may be of even greater concern. When the loss occurs, the bottomhole pressure falls to equal the closing stress between the fracture faces (FCS). The drop in bottom hole pressure 1) may cause the borehole to collapse so that the interval must be re-drilled entirely, or 2) it may allow an influx of hydrocarbon from another zone into the wellbore if it happens to have a pore pressure greater than the reduced bottom hole pressure. This influx results in risky and time-consuming well control operations. A continuous stress-building process minimizes the loss so that it is not necessary to stop drilling, and it also eliminates the drop in bottomhole pressure that can precipitate borehole collapse or a well-control event.
Conventional drilling fluids are designed to have some degree of control over the flow of fluid to the formation permeability, which is referred to as “filtration loss”. When a permeable zone is penetrated, the water or oil that forms the base fluid starts to travel into the pore throats of the formation and the majority of the solids are stripped out and left behind as a filter cake on the wall of the hole. The fluid lost is referred to as filtrate. In common practice, the drilling fluid system is designed to form this filter cake quickly so that the surface is sealed before the cake grows too thick. The purpose of the seal is to reduce the loss of filtrate and to minimize the growth in cake thickness. When a large material, such as LCM, is added to a drilling fluid, the filter cake formed becomes more permeable due to the entrainment of these larger particles. This results in thicker cakes, which increases the potential for stuck pipe. Consequently, operators have avoided adding larger materials to the entire drilling fluid system to avoid the risks associated with a thick filter cake. When high loads of LCM have been used in the past, it has been in conjunction with a base fluid having intrinsically low filtrate loss. However, such attempts at using LCM in a drilling fluid with low filtrate loss characteristics have proven largely unsuccessful at arresting fracture growth.
Two models for lost returns treatment processes with particulate materials (rather than the smaller solid fines of conventional drilling fluids) have been proposed; both focus on the use of specifically sized particles combined with fluid loss control additives to constrain fracture growth. One model is proposed in U.S. Pat. No. 5,207,282 (the '282 Patent), which discloses a loss prevention material (LPM) method that uses a combination of particle sizes to create a bridge near the tip of the propagating fracture to prevent fracture growth. The method requires the use of particle sizes (250-600 micron range) in specific concentrations to form a plug, as asserted in the '282 Patent, near the fracture tip that results in the desired stress increase. The '282 Patent states that “[m]inor amounts of particles outside the critical size range can be tolerated, but the effectiveness is primarily due to presence of an effective amount of particles in the critical size range.” The method also requires filtration loss to the fracture tip be limited so that a low pressure region is created at the extreme tip.
A second proposed model is discussed in U.S. Pat. Application Pub. No. 2006/0254826, which discusses a “stress cage” concept that involves increasing the fracture gradient around a wellbore by creating and packing the opening to the fracture at its intersection with the wellbore. The stress cage concept is similar to the LPM process of U.S. Pat. No. 5,207,282 in that it is also dependent on the use of specifically designed particle sizes to arrest fracture growth. In the stress cage concept, large particles are used that will not enter the fracture opening at the fracture width corresponding to the desired stress increase. A full range of smaller particles are also included to block the area between the larger particles. Bridging materials in the size range of 25 to 2000 micrometers are proposed. Since the large particles cannot enter the fracture and the smaller particles cannot pass the large particles, it is said that material quickly bridges across the fracture opening. The system is also designed to have very low fluid loss (less than 2 ml/30 minutes) so that very little carrier fluid can pass through the particles into the fracture to pressurize it.
The concept is that if the particles cannot enter, and the filtrate cannot pass through, pressure cannot build within the fracture. The pressure within the wellbore will still drive the fracture open but the bridge within the opening prevents pressure transmission. The bridge of solids particles sustains the increased width and associated increase in FCS. Regardless of treatment type, it has been shown that the stress that results from a given fracture width at the wellbore declines as the fracture length extends. The implication for the stress cage method is that it is necessary for the bridge to form very rapidly in order to arrest fracture growth before the fracture lengthens to the point that great width must be blocked in order for the process to succeed. The designed particles may not be large enough to bridge this width, or the required particle size may not be practical to circulate through the components of a typical drilling system. The stress cage concept recognizes that permeability of the surrounding rock plays a role. It has been assumed that if the rate of filtrate leakage through the bridge exceeds the rate of leakage to the permeability exposed in the fracture, pressure will eventually build in the fracture so that it lengthens and the stress at the wellbore will decrease. As a result, U.S. Patent Application Pub. No. 2006/0254826 states the high temperature high pressure (HT/HP) fluid loss from the drilling mud should be less than 2 ml/30 minutes, presumably because this is believed to be adequate control for typical fracture permeability.
A need exists for a process to control lost returns continuously as a well is drilled that is applicable for drilling though low- and/or high-permeability zones that may be depleted in pressure or have low FCS for other reasons. The process would preferably require only products normally used in drilling operations. Because of significant uncertainties in downhole conditions, it is essential the process be sufficiently robust to succeed if actual conditions vary from assumed design conditions. Examples of uncertainties that must be successfully accommodated are the fracture width required to achieve the desired stress increase, fracture length, rock properties, permeability, pore pressure, and variability in execution of field procedures.